Fortnightly - California State University, Fullertonhttp://www.fortnightly.com/tags/california-state-university-fullerton
enMerchant Transmission Reduxhttp://www.fortnightly.com/fortnightly/2006/09/merchant-transmission-redux
<div class="field field-name-field-import-deck field-type-text-long field-label-inline clearfix"><div class="field-label">Deck:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Financial transmission rights and regulated returns have not induced needed construction. Presenting an alternative model.</p>
</div></div></div><div class="field field-name-field-import-byline field-type-text-long field-label-inline clearfix"><div class="field-label">Byline:&nbsp;</div><div class="field-items"><div class="field-item even"><p>J. Jolly Hayden and Robert J. Michaels</p>
</div></div></div><div class="field field-name-field-import-bio field-type-text-long field-label-inline clearfix"><div class="field-label">Author Bio:&nbsp;</div><div class="field-items"><div class="field-item even"><p><b>J. Jolly Hayden</b> is an independent consultant and most recently vice president of transmission operations for Calpine. Contact him at <a href="mailto:jjhayden@sbcglobal.net">jjhayden@sbcglobal.net</a>. <b>Robert J. Michaels</b> is professor of Economics at California State University, Fullerton, and an independent consultant. Contact him at <a href="mailto:rmichaels@fullerton.edu">rmichaels@fullerton.edu</a>. The opinions expressed in this article are the authors’ alone.</p>
</div></div></div><div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">Fortnightly Magazine - September 2006</div></div></div><div class="field field-name-field-import-image field-type-image field-label-above"><div class="field-label">Image:&nbsp;</div><div class="field-items"><div class="field-item even"><img src="http://www.fortnightly.com/sites/default/files/0609-FEA3-fig1.jpg" width="1366" height="744" alt="" /></div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><p>Between 1975 and 1999, transmission investment fell from $5 billion per year (in 2003 dollars) to less than half that amount. It is now on an upward trend, but the 2003 figure (the latest available) is only $4.1 billion.<sup>1</sup> Even if investment increases substantially and stays high, the decline in transmission capacity relative to peak loads will not be reversed quickly.<sup>2</sup> That ratio peaked in 1982, a year when wholesale markets had begun to grow.</p>
<p>By 2004, 75 percent of power generated in the United States went through those markets (this figure does not include some bilateral transactions).<sup>3</sup> Arguments that the system was not “designed” for wholesale transactions are beside the point: They are taking place, providing benefits, and must use the same wires that serve everyone else.</p>
<p>By almost any measure, the nation is running short of transmission, and the existing volume of investment cannot long continue to reliably accommodate retail-load growth and larger wholesale volumes. Factors like environmental opposition also have caused declines and delays in transmission investment, but it seems clear that financial transmission rights (FTRs) and regulated returns have not sufficed to induce the necessary construction.</p>
<h4>LMP and the Value of FTRs</h4>
<p>Uncertainty about the FTRs granted to new transmission lines is only one reason they provide inadequate incentives. Because their value falls with new investment, awarding FTRs to a line builder almost is self-defeating. In the long debate over locational marginal prices (LMP) and FTRs, this consequence largely went unnoticed. Under LMP, the price difference between two nodes equals the difference in their incremental generation costs. (This difference also is the value of an extra megawatt of transmission service between them.) It was thus expected that LMP would provide incentives to locate new generators efficiently and expand transmission where appropriate.</p>
<p>But no one ever adds just 1 MW of transmission capacity. Scale economies remain so great that an efficiently sized upgrade or new line almost invariably will shrink nodal price differences, possibly even to zero. The closer to equality the investment brings prices, the lower the worth of the FTRs it creates, unless a large volume of new rights emerges elsewhere on the system.</p>
<p>Herein is the difference between merchant generation and merchant transmission. The generator earns an income that reflects the additional (marginal) benefits users receive, because its plant is an incremental investment.</p>
<p>The transmission investor that builds on an efficient scale gains only the small post-construction difference in LMPs. This difference equals the congestion cost saved by the last megawatt of new transmission capacity. The upgrade’s full benefits equal the sum of the savings for every megawatt it carries, a figure that is unrelated to the builder’s income. A new line with more capacity produces more benefits for producers and consumers, but smaller FTR-related gains for its builder. Incremental generation benefits both the builder and the consumers of its power. Incremental transmission benefits users but cuts the payoff to its builder. A policy that can align those incentives is more likely to get transmission built than a policy that puts them in opposition.</p>
<h4>The RICC System</h4>
<p>Our proposed policy—reduction in congestion costs (RICC)—rewards transmission investors who lower those costs, with larger rewards for larger cuts. RICC allows any eligible investor (perhaps a hedge fund, an independent power producer, marketer, or large customer) to fund investments in “economically beneficial transmission” (EBT). As in other “participant funding” plans, an RTO or some other planning organization separates projects into those required for reliability and EBT lines that will lower congestion costs. The RTO attends to investment in reliability lines. Utilities have rights of first refusal to construct EBT lines as rate-based investments. Those they choose not to build will qualify for RICC treatment.</p>
<p>An EBT project’s sponsor bears all of its capital costs and associated risks. The upgrade becomes property of the transmission owner (TO), a utility, or an independent transmission company. The TO uses it to deliver power to a load-serving entity (LSE), possibly itself or an affiliate. The sponsor’s RICC income arrives over a contract term of 10 years or some other agreed-upon duration. The RTO computes that income in a shadow settlement process based on avoided congestion costs, described in more detail below. If savings are negative or zero, so is the sponsor’s revenue. All of the affected parties benefit. LSEs in the area are paid a set percentage of the gross congestion savings. The sponsor also pays an administration fee to the RTO, and an operation and maintenance fee to the TO.</p>
<p>To ensure that ratepayers also get a better deal and regulation continues to function, the sponsor’s gross RICC revenue is capped at 95 percent of total costs to ratepayers under traditional rolled-in pricing. RICC also discourages projects that facilitate the exercise of market power. In the savings calculation, any nodal price that increases due to the new line is capped at its old level. The sponsor receives none of the new FTRs that the line creates, which the RTO is free to allocate as it wishes. Upon the contract’s termination, the depreciated line reverts to the TO’s rate base for regulation as usual. A sponsor that fails to recover its costs over the contract period has no regulatory recourse.</p>
<h4>Estimating Savings</h4>
<p>The sponsor’s income is the difference between congestion costs absent the line and those that remain when it is in operation. The latter is no problem, but estimating congestion “but for” the line will require system simulations.</p>
<p>We propose that the RTO perform a daily simulation using the previous day’s load and generation conditions, but with the line removed. In Fig. 1, the height of each bar equals annual congestion costs without the upgrade as calculated by simulation. The orange breakpoint in each bar shows actual congestion. In years 1 through 10, the sponsor shares the area above it with the LSE per their contract. The LSE’s income is unaffected by the sponsor’s payments to the TO and RTO. In years 11 and after the LSE and ratepayers would share all of the saving in congestion costs. Because actual congestion in year 7 exceeds simulated congestion, the sponsor receives no revenue but remains liable for contracted payments to the LSE, TO, and RTO.</p>
<p>The percentage of congestion cost savings that LSEs share is indirectly set by the rule that caps the sponsor’s annual revenue at 95 percent of its value under a rolled-in rate. To maintain the expectations of all interested parties, the percentage should be set in advance and fixed for the life of the contract. We propose running simulations to forecast congestion costs over the contract life and comparing their value if the project is built with their value if it is not built.</p>
<p>The simulations must account for forecasted load growth, as well as new (and abandoned) generation and transmission at their expected dates of operation. The difference between the simulated amounts in each year is an estimate of the sponsor’s revenue absent any regulatory constraints. Subtracting each year’s rolled-in cap from unconstrained revenue and summing allows one to compute the LSEs’ percentage that keeps the sponsor within the rolled-in constraint. RICC encourages efficiency because it gives the sponsor no guarantee of cost recovery, while allowing it to keep every dollar of savings that it earns as a result of efforts to keep its costs down.</p>
<h4>The Benefits of RICC</h4>
<p>There are no apparent obstacles to implementation of RICC in the existing regulatory environment. It is consistent with FERC’s policies, and with RTO planning and queueing processes. Most important, however, RICC promises some of the benefits of competition where its scope has hitherto been severely limited, and reallocation of risk in ways that we see more often in competitive markets than in regulated ones.</p>
<p>RICC is consistent with regulation because it offers a backstop equal to 95 percent of the cost-based rolled-in rate. It also has aspects of a market-based system because the sponsor receives income commensurate with benefits created, but only for a fixed number of years. Since competitive entry into transmission is unlikely to occur, setting a fixed termination year is a reasonable regulatory alternative. Payments to the LSE, TO, and RTO allow them and ratepayers to share the benefits, while properly putting responsibility for cost causation on the sponsor. RICC is an alternative to construction by utilities that in no way limits their future options. Because the sponsor handles all funding and bears most of the risk, there is no need to allocate costs among LSEs as would happen with rate-base transmission. Operations also can be more flexible because there is no need for the common requirement that LSEs take their deliveries at particular nodes.</p>
<p>RICC can be implemented in ways that are minimally disruptive of existing RTO and utility planning processes that forecast growth, solicit generation and transmission, and set project queues. Adding it as an option will have no impact on the process of calculating nodal prices or other aspects of LMP as currently implemented.</p>
<p>As FTR policies continue to evolve, RTOs will remain free to innovate or not innovate as they wish. Since there is only one way to calculate nodal prices, the sponsor’s recovery under RICC and its liabilities to the RTO, TO, and LSE will remain unchanged as institutional changes like these take place.</p>
<h4>Increasing Competition and Reallocating Risk</h4>
<p>Because RICC encourages transmission investments that might not otherwise have been made, it increases the competitiveness of markets and widens their scopes, while posing no threats of market power. RTO rules and FERC regulations ensure that sponsors will be unable to withhold capacity, and a price cap at nodes that are adversely affected ensures that they cannot profit from any incidental congestion their projects cause.</p>
<p>Because RICC offers a new alternative, it will limit further the abilities of vertically integrated utilities (even under an RTO) to exploit system weaknesses that favor their own generation and allow discrimination of access. But competition is more than just a lack of abuses due to market power. Implementing RICC would promote entrepreneurship in an area that has seen little of it. It would motivate the expeditious construction of new lines and upgrades. The winning sponsor would be the first entity that believes it can earn an acceptable return by building it. RICC also rewards more efficient upgrades and better-located lines that are consistent with reliability. If a project can have several configurations, competition for RICC income can incentivize a search for designs that maximize the difference between its costs and benefits.</p>
<p>RICC also reallocates transmission risks as the shift from rate-base plants to non-utility production did for generation risks. Traditional regulation thrust the risks of both onto captive ratepayers, while utility investors enjoyed secure (but relatively low) returns. Today investors in independent power bear the risk that their plants will not pass a market test. Competition both limits their returns and offers the prospect of large rewards for efficient choices. There are limits to competitive transmission that do not exist in generation, because the benefits of a new or upgraded line usually are maximized by building one facility. Unlike generators, competing transmission owners will not enter a market to cut the profitability of existing ones and transfer more of the savings to customers. Economists sometimes say that regulation ideally attempts to bring about a competitive allocation of resources when the market will not provide one. Until now the market has offered few such opportunities in transmission. Behind RICC is the idea that some degree of competition is possible even in transmission, and that it is worth trying.</p>
<p>The nation’s transmission system is closing in on engineering limits that threaten its reliability and economic limits that render it less able to move power on demand through an ever growing set of markets. Regulated rates of return on transmission appear insufficient to attract investment, while the future role of independent transmission companies is not yet clear.</p>
<p>Where competition has been possible, it usually has improved market efficiency and ensured the erosion of high profits as competitors enter. In transmission, however, nodal pricing and natural monopoly interact to reduce the incentives of competitors who are rewarded with FTRs. The RICC proposal facilitates competition by offering investors a reward based not on the costs that remain after construction (as a grant of FTRs does), but on the savings that their investment produces for market participants.</p>
<h4>Investor Relations</h4>
<p>RICC offers any interested investor a multi-year window to earn returns that increase with the efficiency of its project, rather than with the amount invested, as happens under traditional regulation. It is fully consistent with the existing system of regulation and with the continuing role of utilities and independent transmission companies as owners of lines. It also is equitable; LSEs share the benefits from the outset, the costs of RTOs and TOs are covered, risk is shifted from consumers to investors, and there is a well-defined cap on the revenue that a sponsor can collect.</p>
<p>Simple regulatory measures that supplement existing open access and RTO rules can defuse a sponsor’s potential to abuse market power. The simulations that determine saved congestion costs already are a part of every RTO’s operations and planning. A number of regulatory rulemakings will be necessary, but this time the payoff may be a transmission system that has finally moved into step with the rest of its industry.</p>
<p> </p>
<h4>Endnotes:</h4>
<p>1. Edison Electric Institute, EEI Survey of Transmission Investment: Historical and Planned Capital Expenditures (1999-2008), May, 2005 at 3.</p>
<p>2. Edison Electric Institute, U.S. Transmission Capacity: Present Status and Future Prospects, Aug. 2004 at 6. <a href="http://www.eei.org/industry_issues/energy_infrastructure/transmission/USTransCapacity10-18-04.pdf" target="_blank">http://www.eei.org/industry_issues/energy_infrastructure/transmission/USTransCapacity10-18-04.pdf</a>.</p>
<p>3. U.S. Energy Information Administration, Electric Power Annual (Nov. 2005) tables 6.1 and ES. <a href="http://www.eia.doe.gov/cneaf/electricity/epa/epaxlfilees.xls" target="_blank">http://www.eia.doe.gov/cneaf/electricity/epa/epaxlfilees.xls</a> and <a href="http://www.eia.doe.gov/cneaf/electricity/epa/epaxlfile6_2.xls" target="_blank">http://www.eia.doe.gov/cneaf/electricity/epa/epaxlfile6_2.xls</a>. This figure does not include some bilateral transactions. See Vito Stagliano and J. Jolly Hayden, “The Electric Transmission Paradox,” Electricity Journal 17 (Mar. 2004), 37-46.</p>
<p>4. A set of numerical examples, comparisons with conventional regulation, and additional discussion of technical details can be obtained from <a href="mailto:jjhayden@sbcglobal.net">jjhayden@sbcglobal.net</a>.</p>
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<a href="/tags/benefits">Benefits</a><span class="pur_comma">, </span><a href="/tags/edison-electric-institute">Edison Electric Institute</a><span class="pur_comma">, </span><a href="/tags/electric-transmission">Electric Transmission</a><span class="pur_comma">, </span><a href="/tags/energy-information-administration-0">Energy Information Administration</a><span class="pur_comma">, </span><a href="/tags/ferc">FERC</a><span class="pur_comma">, </span><a href="/tags/icc">ICC</a><span class="pur_comma">, </span><a href="/tags/lmp">LMP</a><span class="pur_comma">, </span><a href="/tags/lse">LSE</a><span class="pur_comma">, </span><a href="/tags/payment">Payment</a><span class="pur_comma">, </span><a href="/tags/rto">RTO</a><span class="pur_comma">, </span><a href="/tags/scale-economies">Scale economies</a><span class="pur_comma">, </span><a href="/tags/transmission">Transmission</a><span class="pur_comma">, </span><a href="/tags/us-energy-information-administration">U.S. Energy Information Administration</a><span class="pur_comma">, </span><a href="/tags/california-state-university-fullerton">California State University, Fullerton</a> </div>
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Fri, 01 Sep 2006 04:00:00 +0000puradmin14345 at http://www.fortnightly.comStranded Investment: Utility Estimates or Investor Expectations?http://www.fortnightly.com/fortnightly/1997/06/stranded-investment-utility-estimates-or-investor-expectations
<div class="field field-name-field-import-byline field-type-text-long field-label-inline clearfix"><div class="field-label">Byline:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Steven isser, and Robert Michaels</p>
</div></div></div><div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">Fortnightly Magazine - June 1 1997</div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><p>Ask this question: Are Investors today earning what they thought they would, back when they last had faith in regulation?</p>
<p> </p>
<p>As their customers discover more competitive prices, many utilities remain saddled with the costs of uneconomic plant and power purchase contracts approved under regulation. They seek compensation for these costs, but the amount deserves a close examination.</p>
<p>Some utilities seek remuneration that exceeds the market value of their common stock. Such a settlement seems overly generous for investors, who will continue to own their shares after the payoff. Some utilities with large claims also want a once-and-for-all regulatory determination of the settlement. These utilities want the amount frozen by securitization plans, like those promised in new laws enacted in California and Pennsylvania.</p>
<p>Of course, before regulators can begin to determine how much compensation utilities deserve for stranded costs, they must first determine whether to award any compensation at all. They must also decide which assets deserve payoffs and how utilities ought to dispose of the amounts recovered. The last step, however, is often overlooked: Regulators must design a method of calculating the payoff that promotes efficiency and fairness.</p>
<p>We argue for a reorientation of the stranding debate that emphasizes the fortunes of investors and de-emphasizes the booked costs of utilities. In fact, recovery of expected investor returns should be the basis for a reasonable armistice in the stranded cost wars. If investors are the central actors of the stranding drama, calculations that disregard their fortunes have little claim to primacy in a debate whose stakes are measured in the hundreds of billions.</p>
<p>The calculation, then, should start from forward-looking market data rather than the historical constructs that underlie the lost-revenues and market-to-book methods. Calculations based on investor expectations are conceptually clear and consistent with the realities of finance and power markets. They are already familiar to utilities, regulators and financial analysts, and offer a consistent treatment for the diverse situations of individual utilities.</p>
<p>The Impact of the "Compact"</p>
<p>As the importance of stranded investment became apparent, advocates of full recovery typically faced off against advocates of zero recovery. Those with views between those extremes usually saw a partial payout as a politically expedient strategy rather than a matter of principle. %n1%n The intellectual foundation of full recovery was a metaphorical "Regulatory Compact" that advocates claimed had long governed the industry. Supposedly, this compact guaranteed the returns of utility investors in all but extreme circumstances, because they had forsaken the high risks and high rewards of ordinary stocks for the low risks and low returns of a regulated industry.</p>
<p>On the other side, advocates of zero recovery also noted that the real returns earned by utility investors could hardly be described as "low." They also questioned the veracity of allegations that regulators had at times compelled utilities to make uneconomic investments. If so, as competition arrives, regulators should have no reason to further protect investors from the consequences of decisions by utility management who served at the sufferance of those investors. By contrast, proponents of the Regulatory Compact view incomplete recovery as an uncompensated taking that rises to the status of a constitutional question.</p>
<p>Extrapolating decisions on the regulation of real property to the regulation of utilities is difficult, but the Supreme Court has been generally reluctant to interfere with state-level actions that entail less than a complete taking of a property right or a physical invasion of that property. %n2%n Regarding utilities, the Supreme Court's decision on regulatory disallowances in Duquesne v. Barasch may apply to stranded costs. In that case, the court held that regulators enjoyed wide discretion regarding cost recovery, but suggested that a constitutional issue might arise if uncompensated stranded costs endangered a utility's financial integrity. %n3%n In one recent case, the New York Supreme Court rejected the compact as justification for full recovery, and instead ratified a regulatory decision to determine compensation on a case-by-case basis. %n4%n</p>
<p>If Recovery, How Much?</p>
<p>As a practical matter, regulators and legislators are now coming around to the view that some implied agreement once existed and that some stranded cost recovery is warranted. Given this assumption, one might conclude that ratepayers who left utilities to find their own suppliers breached their obligation to take service. If so, the departing customers could be required to pay "expectation damages" that leave utility investors no worse off than they would have been if the compact had continued to run unabated.</p>
<p>Few participants in the debate have tackled the question of how to compute stranded costs. Some utilities favor charging departing customers amounts that leave revenues intact if the customer had remained in the system. In fact, in its open-access Order 888, the</p>
<p>Federal Energy Regulatory Commission favors this policy for wholesale purchasers who unexpectedly leave utilities. Regulators and legislators have also proposed granting utilities the difference between the booked value of their uneconomic assets and the expected market value of those assets under competition. In California, an important determinant of a utility's compensation will be the amount it receives for plants being divested as part of the transition program.</p>
<p>The lost-revenue calculation and the market-to-book comparison both ignore the returns that investors expected to receive under continuing regulation, and neither examines the outcomes investors actually experienced. If fairness requires payments, then the amount should reflect how compensation affects investors' fortunes rather than how it affects the utility's books.</p>
<p>The Financial Expectations Method</p>
<p>To arrive at compensation to keep utility investors whole, begin with the financial expectations of those who bought utility stock when a consensus still prevailed that the old regulatory scheme would persist indefinitely. Call this idea the "Financial Expectations" method. Since stock prices embody these expectations, find the price as of the last date investors expected regulated returns to persist indefinitely. One possible date is the last state rate case in which neither the utility nor its regulators mentioned a threat of retail competition. Assume that this case was decided in 1989, and retail wheeling was set to begin in 1998. To determine stranded cost recovery, estimate returns to investors over a suitably long period (e.g., 20 years) that bridges the transition from regulation to competition. Use this result to estimate the change in the value of equity due to the coming of competition.</p>
<p>This method requires data on the utility's past performance and its estimated future earnings per share, looking forward from 1989. One can then discount these two figures (past earnings from 1980 to the present; future earnings to 2008) by the rate of return on common equity that regulators authorized in the 1989 rate case. This present value indicates calculated (or "realized") returns after 1989. The 1989 stock price shows the "expected" returns in 1989. If the present value of realized returns is less than the price of the stock in 1989, then investors will not have earned the returns they expected.</p>
<p>If future payouts are required to make investors whole, regulators must determine how to build them into rates and allocate them among customer classes. Since only the present value of payments matter for this proposed method, payments may be made in either a lump sum or a steady stream. Adjustments may prove necessary if the utility's realized future performance diverges significantly from the model's predictions, if, for instance, adverse market conditions bring an unexpected revenue shortfall that renders the utility incapable of meeting its commitments to bondholders.</p>
<p>Any adjustments, however, should be determined as the need arises, rather than as fixed amounts computed in the heat of a transition to a market with an uncertain future. Estimates of unrecoverable plant values are sensitive to assumptions about future market conditions and the speed at which retail competition will spread. %n5%n Once-and-for-all determinations are not necessary for access to capital. Uncertainty about future markets and stranding recoveries has adversely affected the financial health of only a few utilities. %n6%n</p>
<p>Identifying the Benefits</p>
<p>Returning to investors an amount consistent with their expectations under the old regulatory regime is fair, efficient and better grounded in reality than giving them a payoff that depends on the vagaries of regulatory accounting. The Financial Expectations method accounts for the returns long-term investors actually realized in the past and for the returns they are likely to earn after competition comes. It reduces their recovery if their past returns exceeded those authorized by regulators, and augments recovery if past performance fell short.</p>
<p>This method is far from a perfect solution, but may emerge as the best without reopening a decade of regulatory dockets. Ideally, investors should be able to keep supernormal returns made by good management that earlier stranded some investments. Investors should also be denied payments that make up for substandard performance by less competent managements. Retrospective redeterminations, however, are unlikely to impose heavy burdens on scarce regulatory resources in return for questionable benefits.</p>
<p>A reasonable compromise on stranded cost begins by presuming the existence of a Regulatory Compact. Under that compact, however, investors accepted a ceiling on their returns. Fairness to ratepayers requires that they pay no more than is required to give the investors the amounts for which they contracted. These amounts may be quite unlike those calculated by the lost-revenues or market-to-book methods.</p>
<p>A firm, bottom-line number based on regulatory accounting mechanisms should appeal to those who still base their thinking on "revenue requirements." Utilities were once dependable sources of long-term returns, recovering the booked costs of their assets and reinvesting the proceeds to produce secure future income. As the industry moves to market, so must this insistence that it is booked costs rather than market returns that matter to investors. Utilities have one further responsibility about which little has been said: However compensation is paid, along with those payments, utilities must put shareholders on notice that they are now are on their own. t</p>
<p>Steven Isser is a consultant with Hagler Bailly Consulting of Arlington, Va. He holds a Ph.D. in economics from the University of Texas and is currently completing law school there. Robert Michaels is Professor of Economics and California State University, Fullerton, and senior advisor to Hagler Bailly Consulting. He holds a Ph.D. from the University of California, Los Angeles. The views expressed in this article are not necessarily those of the authors' affiliations or clients.</p>
<p> </p>
<p> </p>
<p>Calculating Expectations</p>
<p> </p>
<p>On Jan. 1, 1987, an investor buys one share of stock in Utility X for $100. Assume the stock earns a $10 dividend at the end of every year and is expected to do so forever. Regulators have conveniently set the utility's authorized return on equity equal to the rate on similar safe investments (em 10 percent. The market price of the share will thus be $100, equal to the discounted value of its long-lived stream of future dividends.</p>
<p>Then assume deregulation comes without warning at the end of 10 years of dividend payments, immediately cutting the stock price to $50. How much stranding compensation, if any, is due for stranded costs under each of three different scenarios: 1) constant (expected) end-of-year dividends of $10; 2) a higher (unexpected) annual dividend of $12; or 3) a lower (unexpected) dividend of $8?</p>
<p>1. Constant Dividend.</p>
<p>For 10 years, the stock fulfills the investor's expectations, with $10 dividends paid annually. The price remains steady at $100. (Capital gains are omitted here but can be included at the cost of algebraic complexity.) Just after the 1997 end-of-year dividend is paid, however, instant deregulation occurs and the $100 price falls to $50 on Jan. 1, 1998. If, on that date, the investor sells the share at $50 and receives $50 for stranded costs, he will still have $100 in assets, as expected on the purchase date of the stock:</p>
<p>[$10 ( 1.10] + [$10 ( (1.10)²] + ... [$10 ((1.10)10 ] + [($50) ( (1.10)10] + [($50) ( (1.10)10] = $100</p>
<p>The final three terms are the Dec. 31 dividend payment, the Jan. 1 sale price of the stock and the Jan. 1 receipt of stranding compensation.</p>
<p> </p>
<p>2. Rising Dividend.</p>
<p> </p>
<p>Next, assume that just after the investor bought the stock for $100 on Jan. 1, 1987, the utility raised its dividend to $12 per year while its cost of capital remained the same. (This situation is realistically more akin to capital gains.) As before, after 10 years of $12 dividends, sudden deregulation depresses the stock price to $50. An investor who also receives an additional $50 for strandings is overcompensated relative to expectations at the time of purchase. Stranding compensation of $18.15 is all that is necessary to fulfill his 1987 expectations:</p>
<p>[$12 ( 1.10] + [$12 ( (1.10)²] + ... [$12 ((1.10)10 ] + [($50) ( (1.10)10]+ [($18.15) ( (1.10)10] = $100</p>
<p>3. Falling Dividend.</p>
<p> </p>
<p>This method can also calculate compensation for investors whose expectations were frustrated (presumably not because of utility imprudence). Just after the investor buys the stock, dividends fall to $8 and continue at that level over the first 10 years. Just after the tenth dividend payment, the stock price falls to $50 with deregulation. Now a Jan. 1, 1998 stranding payment of $81.88 leaves the investor with an income stream that has a present value of $100, looking forward from 1987:</p>
<p>[$8 ( 1.10] + [$8 ( (1.10)²] + ... [$8 ((1.10)10 ] + [($50) ( (1.10)10] + [($81.88) ( (1.10)10] = $100</p>
<p> </p>
<p>1For polar views, see William J. Baumol &amp; J. Gregory Sidak, Transmission Pricing and Stranded Costs in the Electric Power Industry (Wash. D.C.: AEI Press, 1995), and Robert J. Michaels, "Unused and Useless: The Strange Economics of Stranded Investment," 7 Electricity Journal 12 (Oct. 1994), 12-22. On what utilities should do with the funds, see Robert Michaels, "After Stranding Recovery, What?," PUBLIC UTILITIES FORTNIGHTLY, June 1, 1996, 14-16.</p>
<p>2See J. Gregory Sidak and Daniel F. Spulber, Deregulatory Takings and Breach of the Regulatory Contract, 71 N.Y.U. Law Review 851 (1996); Lucas v. South Carolina Coastal Council, 112 S. Ct. 2886 (1992)[deprivation of all economically beneficial use required]; Yee v. City of Escondido, 112 S.Ct. 1522 (1992)[upholding rent control]; but see Dolan v. City of Tigard, 114 S.Ct. 2309 (1994).</p>
<p>3Duquesne Light Co. v. Barasch, 488 U.S. 299, 312-314 (1988).</p>
<p>4Energy Asso. of New York State et al., v. New York PSC, 653 N.Y.S.2d 502, 174 PUR4th 406 (Sup.Ct.1996).</p>
<p>5Moody's recent update of a 1996 report showed little change in aggregate stranded costs, but estimates for over 75 percent of utilities changed by more than 10 percent over the year. "New Moody's Survey Shows Many Changes in Estimated Stranded Costs and Prices," Electric Utility Week, Jan. 27, 1997, 11.</p>
<p>6Donaldson, Lufkin, and Jenrette, Electric Utility Company Outlook, Dec. 1996. Some utilities with large exposures have claimed that less than full recovery will lead them into insolvency, or, at worst, bankruptcy.</p>
<p> </p>
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Sun, 01 Jun 1997 04:00:00 +0000puradmin10186 at http://www.fortnightly.comElectricity Utility Mergers: The Answer or the Question?http://www.fortnightly.com/fortnightly/1996/01/electricity-utility-mergers-answer-or-question
<div class="field field-name-field-import-byline field-type-text-long field-label-inline clearfix"><div class="field-label">Byline:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Robert J. Michaels</p>
</div></div></div><div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">Fortnightly Magazine - January 1 1996</div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><p>Differences of opinion make for good horse races and bad jokes about economists, and those who are studying the recent wave of electric utility merger announcements have not let us down. Some of these economists optimistically believe that the mergers act as forces for competition, since they will combine corporate assets and staffs to bolster operating efficiency and market acumen at the merged companies. Other economists, who see transmission as the root of monopoly power, are more pessimistic. They expect that a merged system controlling more transmission will end up better able to deny competitive access and thereby harm competition. Most likely, both of these views will turn out to be incorrect or incomplete.</p>
</p>
<p> Optimists should note that the announced savings from utility mergers are small, speculative, and often obtainable by less drastic means. Regulation makes it unlikely that a merged system will create a more formidable rival to independent generators, marketers, or telecommunications purveyors. Pessimists should note that the Energy Policy Act of 1992 (EPAct) put important limits on transmission monopoly by empowering the Federal Energy Regulatory Commission (FERC) to issue wheeling orders. Those limits will become more stringent as the FERC gears up to compel utilities of all sizes to file open-access transmission rates. </p>
<p> Neither monopoly nor competition seems to explain the recent merger rush. Combining two large utilities can prove costly, time-consuming, and disruptive. At a time when management should prepare for market developments, a merger diverts its attention to a transaction of little apparent value. In ordinary markets, mergers, acquisitions, and takeovers can be productive, but here they seem otherwise. Utilities that merge may be preparing for politics rather than competition. </p>
<p> HOW HIGH THE SAVINGS? </p>
<p> The substantial savings projected for recent mergers largely reflect the size of the merging systems, which often announce their newfound efficiency in ways that encourage a sense of wonderment in lay onlookers. Merger announcements never discount expected savings to a present value so that the returns to a merger can be compared with returns on other investments. The announcements give only one figure, rather than a range that might account more accurately for the greater risks that will come with increased competition. They also omit any explicit accounting for regulatory risk. If recent experiences are typical, most mergers will require about two years to obtain the necessary regulatory and antitrust approvals. If any one agency disapproves, the merger may never take place. If an agency imposes unexpected conditions on the merger, some of the anticipated savings might also vanish. </p>
<p> Even without these qualifications, the claimed savings are never very substantial. The annualized $770-million, 10-year savings for Southwestern Public Service Co. and Public Service Co. of Colorado amount to 2.6 percent of current electric revenues and 1.2 percent of the book value of their assets. Since the two companies do not abut, they must link themselves with a 300-mile line costing several hundred thousand dollars a mile. Northern States Power Co. and Wisconsin Energy Co. expect $2 billion in savings over the next 10 years (3.3 percent of annual revenue); Potomac Electric Power Co. and Baltimore Gas and Electric Co. expect to save 2.6 percent of revenues. (Some of these companies also distribute gas.) Unregulated companies do not merge to save such small percentages of income. </p>
<p> Utility projections of merger-related savings are understandably optimistic, and will probably differ from those calculated by opponents. Yesterday's utility could project with more confidence than today's because its income stream, cost recovery, and political situation were all more secure than they are ever likely to be again. Some of today's utilities find themselves in tough situations because past projections of revenue and costs have not come true. Even if a merged utility realizes the savings, investors will not prosper if regulators insist on a passthrough to ratepayers. As for the ratepayers, let's assume that electricity makes up 5 percent of production costs (a very high share) for an industrial customer: A 2-percent post-merger price fall lowers that customer's total costs by only one-tenth of one percent. </p>
<p> LEAN AND MEANINGFUL? </p>
<p> Most savings from electric mergers are to come from sources that seldom motivate mergers elsewhere. In most announcements, two-thirds or more of the savings stem from staff reductions, investment deferrals, and related consolidations. Consider that fact. Utility-owned generation may have lost its natural monopoly, but the workforce of the merged companies has now become one. Any unmerged company that can only eliminate redundant employees by merger is a company with poorly designed job responsibilities. Oddly, merging utilities seldom target specific staff or functions for elimination. Instead, they intend to replace employees who depart voluntarily, and to fill in the vacancies by reassigning those who remain. If downsizing by employee attrition was good competitive strategy, unregulated businesses would use it more often. Ordinary firms, however, will more likely merge to acquire desirable employees rather than to lose them at random. </p>
<p> Only in odd situations will a merger leave the product better "positioned" for competition. In bulk generation, if one party enjoys an excess of low-cost generation while the other does not, regulators might insist on allocating the inexpensive power to native load. If neither partner can compete in the generation market by itself, a company that controls the aggregate of their generation also probably cannot. A merger cannot give a "first-mover" advantage in an industry where the important first moves have already been made. A merger between two utilities might employ their complementary skills for competitive advantage, but merger announcements seldom indicate what those skills might be. </p>
<p> A merger might allow some component of Utility A to function more effectively by embedding it into a combination of Utilities A and B. Utility B, however, might acquire the function more cheaply by contract than by merger, without combining other activities that a merger would disadvantage. If Utility A covets a particular piece of Utility B, it can buy just that piece, contract to share it, hire away the key personnel, or build its own on the same pattern. Electric utilities show a long record of ingenious and productive contracting. They routinely arrange diverse bulk-energy trades with one another, invest jointly in generation and transmission, share short-term capacity, and make contracts for a variety of wheeling and coordination services. Why should two utilities merge if they can arrange almost any efficient transaction by contract? If merging really saves hundreds of millions, why did utilities rely on contracts for so long, and why were managements and regulators so slow to notice the savings? </p>
<p> CAN A MERGER MONOPOLIZE? </p>
<p> Some commentators fear (and some utilities may hope) that a merged system will exert greater monopoly power over transmission. If a utility cannot profitably exploit its transmission before merging, however, it probably cannot do so afterwards. A monopoly can only overcharge if it restricts product availability, a difficult feat for a utility with obligations to serve at cost-based rates. Under open access, the withholding of transmission is unlikely, particularly if wheeling customers can reassign their rights and utilities must offer interruptible service on unused capacity. Whether or not mergers occur, utilities may soon have to surrender some of their control to regional transmission groups and wholesale pools. </p>
<p> Open access might alleviate transmission restrictions, but a larger post-merger utility could wield more monopoly power in energy than a smaller one. In bulk power, the FERC increasingly assumes that wholesale generation markets are competitive. A merger only harms competition in those markets if it somehow forecloses transmission-dependent systems from transacting beyond the merged territory. If there are such impediments, a fine-tuning of open-access policy may be in order. At retail, regulation will continue, and antitrust action remains possible. Mergers will not affect state regulations that restrict retail direct access or otherwise require final users to pay above-market prices. Larger utilities will only be able to exercise monopoly power at retail if state regulators let it happen. </p>
<p> ARE MERGERS LIKE TAKEOVERS? </p>
<p> An economically efficient business produces at low cost. It encompasses the right scope of activities and sells its product competitively. Efficiency grows more likely if investors actively compete for control of the business, since those who can better operate it will outbid others. </p>
<p> Investors can choose from numerous methods to compete for corporate control. A proxy fight may vote out an inept management, a well-run existing firm may acquire an ineptly run firm, or a merger may combine one firm's executives with another's. Most graphically, a takeover specialist can acquire stock and install management of its choice. This new leadership often changes the firm's financial structure and reshapes its scope by divesting inappropriate activities. In theory and practice, takeovers usually improve efficiency and make corporations more valuable. The financial restructuring puts investment decisions under closer scrutiny by the capital markets. </p>
<p> Today's mergers between adjacent utilities hardly serve as efficient takeovers. No recent announcement even hints that one partner has less than superb management, although it seems odd that so many good matches have only arisen so recently. No merging parties have announced corporate restructurings beyond such easy steps as the formation of a holding company. Merging utilities may often be unable to propose more radical changes. Regulation often restricts their corporate structures and imposes service obligations they cannot abandon. Bond indentures can add another expensive barrier. </p>
<p> Restrictions posed by the Public Utility Holding Company Act (PUHCA) further restrict competition for the control of electric systems. For all practical purposes, PUHCA limits a utility's potential merger partners to adjacent utilities or systems that can be reached by short transmission links. Acquisition of a utility by a nonutility seems unlikely, since doing so will trigger additional regulation of the acquirer's nonutility operations and finance. If Congress repeals or amends PUHCA, utilities may find it difficult to justify the current crop of mergers to shareholders. The utility that waits another year or two may gain important new choices without losing many of the old ones. </p>
<p> Unlike an ordinary corporation, an electric utility does not face a world of potential takeover artists who might impose radical change. Instead, only a few nearby entities in the same business can seriously think about merger or acquisition. It is little wonder that most utility mergers are "friendly," since they take place between long-time neighbors whose past has seldom been competitive. (PECO recently abandoned the only unfriendly transaction in the current crop (em its attempted acquisition of Pennsylvania Power and Light.) The friendliness of most mergers leads to concerns far removed from competition. Writing in The Electricity Journal (Oct. 1995, p. 11), utility merger attorney Douglas Hawes stated that the most important obstacle to a merger of "equal" utilities "is the difficulty of devising a succession plan that satisfies both the two CEOs and their respective boards." Recently consummated mergers have "all involved a contractually blessed plan of one CEO serving as CEO of the combined enterprise for a limited time, to be followed by the other CEO." Facing a maelstrom of retail wheeling and strandings that threaten billions in assets, utilities are choosing merger partners by the ages of their CEOs. </p>
<p> DO MERGERS MATTER? </p>
<p> Economic reasoning usually starts from a presumption that people are self-interested and pursue their interests as best they can. The owners of a business might do so by reshaping it into a better competitor, or possibly a better monopolist. Many of today's utility mergers, however, seem destined to do neither. One possibility remains. </p>
<p> Mergers or none, the future of the industry will be determined both by markets and by politics. Utilities with heavy stranding exposures or competitively aggressive neighbors may find it better to depend on politics than on markets to ensure their continued corporate existence. CEO James Rogers of CINergy Corp. recently stressed this proactive aspect of electric mergers, saying that they will produce "companies that are big enough to mold and shape future regulatory and legislative issues." (Inside FERC's Gas Market Report, Sept. 22, 1995) If Rogers is correct, then what merged utilities cannot get from customers with choices they will attempt to get from governments that restrict those choices. </p>
<p> More optimistically, even politics may not do much for the newly merged systems. A larger utility is both a better fortress and an easier target. Politically, small municipal and cooperative systems have more than held their own, while companies the size of the Long Island Lighting Co. may soon be socialized. Size was of little help to AT&amp;T after competition became strong enough. Competition is emerging everywhere in the industry, in the face of determined opposition from established utilities. Today's mergers will not stop market forces, and they will not turn utilities into market forces of their own. Mergers do not necessarily produce political momentum. Nor is political inertia guaranteed by creating companies that are "too big to fail." If two merging utilities intend to build an ark for themselves, they should understand that the next flood will last longer than 40 days. t </p>
<p> Robert J. Michaels is a professor of economics at California State University, Fullerton, and a consultant at JurEcon, Inc. His research and commentaries on utility competition have often appeared in the FORTNIGHTLY and elsewhere. He is author of the entries on electricity and gas regulation in the Fortune Encyclopedia of Economics (Warner Books, 1993). The views expressed in this article are not necessarily those of his affiliations or clients.</p>
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<a href="/tags/att">AT&amp;T</a><span class="pur_comma">, </span><a href="/tags/baltimore-gas-and-electric">Baltimore Gas and Electric</a><span class="pur_comma">, </span><a href="/tags/commission">Commission</a><span class="pur_comma">, </span><a href="/tags/congress">Congress</a><span class="pur_comma">, </span><a href="/tags/economics">Economics</a><span class="pur_comma">, </span><a href="/tags/energy-policy-act">Energy Policy Act</a><span class="pur_comma">, </span><a href="/tags/energy-policy-act-1992">Energy Policy Act of 1992</a><span class="pur_comma">, </span><a href="/tags/epa">EPA</a><span class="pur_comma">, </span><a href="/tags/epact">EPAct</a><span class="pur_comma">, </span><a href="/tags/federal-energy-regulatory-commission">Federal Energy Regulatory Commission</a><span class="pur_comma">, </span><a href="/tags/federal-energy-regulatory-commission-ferc">Federal Energy Regulatory Commission (FERC)</a><span class="pur_comma">, </span><a href="/tags/ferc">FERC</a><span class="pur_comma">, </span><a href="/tags/ge">GE</a><span class="pur_comma">, </span><a href="/tags/james-rogers">James Rogers</a><span class="pur_comma">, </span><a href="/tags/long-island-lighting-co">Long Island Lighting Co.</a><span class="pur_comma">, </span><a href="/tags/open-access">Open access</a><span class="pur_comma">, </span><a href="/tags/peco">PECO</a><span class="pur_comma">, </span><a href="/tags/potomac-electric-power">Potomac Electric Power</a><span class="pur_comma">, </span><a href="/tags/public-service-co-colorado">Public Service Co. of Colorado</a><span class="pur_comma">, </span><a href="/tags/regulation">Regulation</a><span class="pur_comma">, </span><a href="/tags/ver">VER</a><span class="pur_comma">, </span><a href="/tags/california-state-university-fullerton">California State University, Fullerton</a> </div>
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Mon, 01 Jan 1996 05:00:00 +0000puradmin8234 at http://www.fortnightly.com